Self-calibrated method of determining borehole fluid acoustic properties

ABSTRACT

Methods, systems, and devices for determining an acoustic parameter of a downhole fluid using an acoustic assembly. Methods include transmitting a plurality of pulses; measuring values for at least one wave property measured for reflections of the plurality of pulses received at at least one acoustic receiver, including: a first value for a first reflection traveling a first known distance from a first acoustically reflective surface having a first known acoustic impedance, a second value for a second reflection traveling a second known distance substantially the same as the first known distance from a second acoustically reflective surface having a second known acoustic impedance, and a third value for a third reflection traveling a third known distance from a third acoustically reflective surface having a third known acoustic impedance substantially the same as the second acoustic impedance; and estimating the acoustic parameter using the values.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a division of U.S. patent application Ser. No.16/351,145, filed on Mar. 12, 2019, the disclosure of which isincorporated herein by reference in its entirety.

FIELD OF THE DISCLOSURE

This disclosure generally relates to borehole tools, and in particularto methods and apparatuses for estimating a parameter of interest of adownhole fluid.

BACKGROUND OF THE DISCLOSURE

Determining the acoustic properties of downhole fluids may be desirablefor several types of downhole evaluation. Such properties may be used incharacterizing the fluid itself, or for use in methods for evaluatingthe formation, the borehole, the casing, the cement, or for previous orongoing operations in the borehole including exploration, development,or production.

For many of these techniques, it is desirable that variations in fluidsfilling the borehole (e.g., drilling fluid) be compensated for, becauseconventional processing is highly sensitive to the properties of thedrilling fluid.

Thus, various techniques are currently employed to determine parametersof the fluid affecting acoustic measurements, such as acoustic impedanceand sound speed, in order to interpret acoustic measurement data.Traditionally, time of flight of the acoustic signals traveling througha known pathlength of fluid has been used to determine sound speed, andadditional measurements may be used to estimate at least one of acousticimpedance and density of the fluid.

SUMMARY OF THE DISCLOSURE

In aspects, the present disclosure is related to methods and apparatusesfor determining a fluid's acoustic properties such as sound speed,acoustic impedance, and acoustic attenuation independent of an acoustictransducer's transmitted intensity or detection sensitivity by usingmore than one transducer and more than one reflector and by solving aset of simultaneous equations to determine these acoustic properties.

Aspects include methods of determining an acoustic parameter of adownhole fluid using an acoustic assembly comprising a plurality ofacoustic reflectors each having at least one acoustically reflectivesurface at least partially immersed in the downhole fluid. Methods mayinclude transmitting a plurality of pulses; measuring values for atleast one wave property measured for reflections of the plurality ofpulses received at at least one acoustic receiver; and estimating theacoustic parameter using the values. The values may include a firstvalue for a first reflection traveling a first known distance from afirst acoustically reflective surface having a first known acousticimpedance; a second value for a second reflection traveling a secondknown distance substantially the same as the first known distance from asecond acoustically reflective surface having a second known acousticimpedance substantially different than the first acoustic impedance; anda third value for a third reflection traveling a third known distancesubstantially different from each of the first distance and the seconddistance from a third acoustically reflective surface having a thirdknown acoustic impedance substantially the same as the second acousticimpedance. The plurality of pulses and the reflections are eachtransmitted through the downhole fluid. Each of the first value, thesecond value, and the third value may be substantially different fromothers of the first value, the second value, and the third value. Atleast two of the first reflection, the second reflection, and the thirdreflection may be reflections of a particular pulse.

The first known distance may be a distance from the first acousticallyreflective surface to an acoustic receiver during the measuring, thesecond known distance may be a distance from the second acousticallyreflective surface to the acoustic receiver during the measuring, andthe third known distance may be a distance from the third acousticallyreflective surface to the acoustic receiver during the measuring. Theacoustic receiver may be configured to rotate about an axis of theassembly; the first acoustically reflective surface, the secondacoustically reflective surface, and the third acoustically reflectivesurface may be azimuthally distributed about the axis, such that each ofthe first reflection, the second reflection, and the third reflectioneach return to the acoustic receiver from a different azimuth withrespect to the axis.

Aspects may include apparatus for determining an acoustic parameter of adownhole fluid in a borehole. Apparatus may include a tool havingdisposed thereon an acoustic assembly, the acoustic assembly comprisingat least one transducer and a plurality of acoustic reflectors havingacoustically reflective surfaces. The tool may be configured to at leastpartially immerse at least one transducer and the acousticallyreflective surfaces, and wherein the acoustic assembly is configured toi) transmit a plurality of pulses through the fluid, and ii) measurevalues for at least one wave property for reflections of the pluralityof pulses, including: a first value for a first reflection traveling afirst known distance from a first acoustically reflective surface havinga first known acoustic impedance; a second value for a second reflectiontraveling a second known distance substantially the same as the firstknown distance from a second acoustically reflective surface having asecond known acoustic impedance substantially different than the firstacoustic impedance; and a third value for a third reflection traveling athird known distance substantially different from each of the firstdistance and the second distance from a third acoustically reflectivesurface having a third known acoustic impedance substantially the sameas the second acoustic impedance. Apparatus may include a processorconfigured to estimate the acoustic parameter using the values. The atleast one transducer may be configured to rotate about an axis of theassembly; and the first acoustically reflective surface, the secondacoustically reflective surface, and the third acoustically reflectivesurface may be azimuthally distributed about the axis, such that each ofthe first reflection, the second reflection, and the third reflectioneach return to the acoustic receiver from a different azimuth withrespect to the axis.

Aspects include a method of determining an acoustic parameter of adownhole fluid using an acoustic assembly comprising a plurality ofacoustic reflectors each having at least one acoustically reflectivesurface at least partially immersed in the downhole fluid. Methods mayinclude estimating the acoustic parameter using a value for at least onewave property measured for: a first reflection received at a firstacoustic receiver (R1) of a first pulse from a first acousticallyreflective surface located a first distance from the first acousticreceiver; a second reflection received at the first acoustic receiver(R1) of the first pulse from a second acoustically reflective surfacelocated a second distance from the first acoustic receiver differentthan the first distance; a first reflection received at a secondacoustic receiver (R2) of a second pulse from a third acousticallyreflective surface located a third distance from the second acousticreceiver; and a second reflection received at the second acousticreceiver (R2) of the second pulse from a fourth acoustically reflectivesurface located a fourth distance from the second acoustic receiverdifferent than the third distance. The first pulse, the first reflectionof the first pulse, the second reflection of the first pulse, the secondpulse, the first reflection of the second pulse, and the secondreflection of the second pulse may each be transmitted through thedownhole fluid. Methods may further comprise transmitting acousticpulses using at least one acoustic transducer to generate the pluralityof acoustic pulse reflections.

The at least one wave property may comprise travel time and amplitude.The first acoustically reflective surface may comprise a portion of afirst acoustic reflector having a first impedance value and the secondacoustically reflective surface may comprise a portion of a secondacoustic reflector having a second impedance value substantially thesame as the first impedance value. The third acoustically reflectivesurface may comprise a portion of a third acoustic reflector having athird impedance value and the fourth acoustically reflective surface maycomprise a portion of a fourth acoustic reflector having a fourthimpedance value substantially different than the third impedance value.The fourth impedance value may be substantially the same as at least oneof: i) the first impedance value, and ii) the second impedance value.

The third acoustically reflective surface may comprise a portion of athird acoustic reflector having a third impedance value and the fourthacoustically reflective surface may comprise a portion of a fourthacoustic reflector having a fourth impedance value substantiallydifferent than the third impedance value. The first acousticallyreflective surface may comprise a portion of a first acoustic reflectorhaving a first impedance value and the third acoustically reflectivesurface may comprise another portion of the first acoustic reflectorhaving the first impedance value.

The first distance may be less than the second distance and the thirddistance may be less than the fourth distance, and estimating theacoustic parameter may comprise estimating an acoustic impedance for thedownhole fluid using an impedance of the third acoustically reflectivesurface and an impedance of the fourth acoustically reflective surfacedifferent than the impedance of the third acoustically reflectivesurface. The third acoustically reflective surface may comprise a loweracoustic impedance material and the fourth acoustically reflectivesurface may comprise a high acoustic impedance material.

Estimating the acoustic parameter may comprise estimating an acousticimpedance for the downhole fluid using a ratio of a first product of thefirst reflection received at the first acoustic receiver and the secondreflection received at the second acoustic receiver to a second productof the second reflection received at the first acoustic receiver and thefirst reflection received at the second acoustic receiver. The firstdistance may be less than the second distance and the third distance maybe less than the fourth distance.

Estimating the acoustic parameter may comprise estimating an attenuationcoefficient for the downhole fluid using a ratio of a first value for asplit-signal amplitude of the first reflection received at the firstacoustic receiver and a second value for a split-signal amplitude of thesecond reflection received at the first acoustic receiver.

The apparatus may be further configured to carry out method embodimentsas described herein. For example, the processor may be configured tocarry out the methods described above.

Further embodiments may include a non-transitory computer-readablemedium product having instructions thereon that, when executed, cause atleast one processor to perform a method as described above. Thenon-transitory computer-readable medium product may include at least oneof: (i) a ROM, (ii) an EPROM, (iii) an EEPROM, (iv) a flash memory, or(v) an optical disk.

Examples of some features of the disclosure may be summarized ratherbroadly herein in order that the detailed description thereof thatfollows may be better understood and in order that the contributionsthey represent to the art may be appreciated.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed understanding of the present disclosure, reference shouldbe made to the following detailed description of the embodiments, takenin conjunction with the accompanying drawings, in which like elementshave been given like numerals, wherein:

FIG. 1 shows a device in accordance with embodiments of the presentdisclosure.

FIG. 2 shows another device in accordance with embodiments of thepresent disclosure.

FIGS. 3A-3C show another device in accordance with embodiments of thepresent disclosure.

FIGS. 4A-4D show beam modeling resulting in accordance with embodimentsof the present disclosure.

FIGS. 4E-4G show example measured waveforms illustrating results ofemploying techniques of the present disclosure.

FIG. 5 is a schematic diagram of an exemplary drilling system accordingto one embodiment of the disclosure.

FIG. 6 illustrates an acoustic logging tool in accordance withembodiments of the present disclosure.

FIG. 7A illustrates variations in acoustic impedance with echo amplituderatio for weak reflectors of various impedances.

FIG. 7B illustrates variations in acoustic impedance with echo amplituderatio for strong reflectors of various impedances.

FIG. 7C illustrates effects of transducer sensitivity differences.

FIG. 8A shows a flow chart of a method for determining an acousticparameter of a downhole fluid in accordance with embodiments of thepresent disclosure.

FIG. 8B shows a flow chart of a method for determining an acousticparameter of a downhole fluid in accordance with embodiments of thepresent disclosure.

DETAILED DESCRIPTION

In aspects, this disclosure relates to estimating a parameter ofinterest of a downhole fluid in an earth formation intersected by aborehole. The at least one parameter of interest may include, but is notlimited to, one or more of: (i) sound speed of the fluid, (ii)attenuation coefficient of the fluid; and iii) acoustic impedance of thefluid.

Various techniques have been used to analyze downhole fluids. Suchtechniques may include the use of instruments for obtaining informationrelating to a parameter of interest in conjunction with sample chambersstoring the sampled fluid for analysis or sample chambers allowing thefluid to pass through (continuously, or as directed by a flow control)for sampling, or as mounted on an exterior of a tool body of a downholetool. Example systems may use a signal generator and sensor (which maybe combined; e.g., a transducer) for determining acoustic impedance. Inthe well-known time of flight method, the sound speed, c, of a fluid maybe determined by dividing the travel time of the signal through thefluid by the distance the signal traveled through the fluid.

Currently, both LWD and wireline tools exist which may estimate mudacoustic velocity from empirical formulas based on downhole mud type,weight, temperature, pressure, mud salinity, etc., for standoff andcaliper measurements. However, the inherent limitations of these typesof methods result in relatively large errors (up to +/−20 percent). Thismay stem from the modeling inaccuracies of empirical formulas fromlimited data bases, lack of accounting for cuttings and gas, and so on.Fluid acoustic impedance and attenuation properties influence signalstrength. Accurate measurement of the two properties is often difficultdue to the combined and confounding effects of acoustic impedancemismatch and acoustic attenuation on reducing the amplitudes of thereturned echoes. Signal strength varies with transducer sensitivity,which often drifts with temperature and pressure downhole. Moreover,when multiple transducers are used (even those of the same design andproduction run), variations in response of up to 15 percent or more mayoccur. Resonant plate methods measure acoustic speed in drilling fluidusing one fixed metal reflector located in front of a transducer. See,for example, U.S. Pat. No. 6,957,700. Wireline rotational transducerassemblies for mud velocity calibration and impedance measurement areknown. These assemblies estimate acoustic impedance in the fluid byanalyzing measured reverberation signals and comparing to theoreticalestimates. These methods cannot measure fluid attenuation coefficients,and need constant recalibration for sound velocity measurement. Methodsknown in the art are unable to resolve measurements for impedanceindependent of transducer similarity.

In typical reflective measurements of acoustic signals in a fluid, thereflected signal strength from each target is dependent upon not onlythe attenuation in the fluid, but also the acoustic impedance mismatchof the fluid and the target materials used. The signal amplitudes mayalso be affected by drive voltage, transducer sensitivity variation dueto individual units and downhole conditions (temperature, pressure,etc.). The signal amplitudes may also be affected by transducer beamgeometric and diffraction effects. For reliable and accurate fluidproperty measurement, these effects must be calibrated or corrected. Arobust and accurate method for determining the sound velocity, acousticimpedance, and attenuation coefficient in borehole fluid in situ, whileproviding self-calibration of transducer responses, would be desirable.

The present application relates to methods of determining an acousticparameter of a downhole fluid using an acoustic assembly comprising aplurality of acoustic reflectors each having at least one acousticallyreflective surface at least partially immersed in the downhole fluid.Acoustic transducers are positioned to be at least partially immersed inthe fluid, and configured to provide acoustic pulses to the fluid thatpropagate within the fluid to generate a plurality of acoustic pulsereflections from the reflectors. Although two transducers are shown,more transducers (and/or reflectors) may be used.

Techniques described herein are applicable for LWD, open-hole andcased-hole wire-line applications (e.g., casing and cement bondevaluation), standoff/caliper applications for nuclear density andneutron porosity, open-hole and cased-hole imaging, sonic loggingapplications, and so on. For cased-hole applications, the fluid acousticsound velocity may be employed in determining casing standoff (innerdiameter), casing wall thickness, and casing wear estimates. As a keymodel input parameter, more accurate fluid acoustic impedance improvesthe accuracy of cement acoustic impedance inversion using model-basediteration. Example applications for fluid acoustic properties mayinclude borehole fluid identification and characterization, formationfluid sampling analysis, drilling dynamic event monitoring (gas bubbles,kicks, cuttings, etc.), and borehole washout and fracture imaging. Seefor example, Hayman et al, High-Resolution Cementation and CorrosionImaging by Ultrasound, and U.S. patent application 2008/0189041 toFroelich.

FIGS. 1-3C show devices in accordance with embodiments of the presentdisclosure. Devices may be employed in carrying out the methods of thepresent disclosure. Aspects may include determining an acousticparameter of a downhole fluid using an acoustic assembly comprising aplurality of acoustic reflectors each having at least one acousticallyreflective surface at least partially immersed in the downhole fluid.Thus, devices may include this assembly or may be part of a systemincluding the assembly. Methods may include transmitting a plurality ofpulses; measuring values for at least one wave property measured forreflections of the plurality of pulses received at at least one acousticreceiver, and estimating the acoustic parameter using the values. Theplurality of pulses and the reflections may each be transmitted throughthe downhole fluid.

The measured values may include a first value for a first reflectiontraveling a first known distance from a first acoustically reflectivesurface having a first known acoustic impedance; a second value for asecond reflection traveling a second known distance substantially thesame as the first known distance from a second acoustically reflectivesurface having a second known acoustic impedance substantially differentthan the first acoustic impedance; and a third value for a thirdreflection traveling a third known distance substantially different fromeach of the first distance and the second distance from a thirdacoustically reflective surface having a third known acoustic impedancesubstantially the same as the second acoustic impedance. The uniquedissimilarities in the wave properties of reflections from these threereflectors allow for the determination of acoustic fluid properties,including fluid impedance.

FIGS. 1 & 2 disclose a static assembly which may include no movingparts. Methods employing devices similar to FIGS. 1 & 2 may includeestimating the acoustic parameter using a value for at least one waveproperty measured for each of: a first reflection received at a firstacoustic receiver (R1) of a first pulse from a first acousticallyreflective surface located a first distance from the first acousticreceiver; a second reflection received at the first acoustic receiver(R1) of the first pulse from a second acoustically reflective surfacelocated a second distance from the first acoustic receiver differentthan the first distance; a first reflection received at a secondacoustic receiver (R2) of a second pulse from a third acousticallyreflective surface located a third distance from the second acousticreceiver; and a second reflection received at the second acousticreceiver (R2) of the second pulse from a fourth acoustically reflectivesurface located a fourth distance from the second acoustic receiverdifferent than the third distance. The first pulse, the first reflectionof the first pulse, the second reflection of the first pulse, the secondpulse, the first reflection of the second pulse, and the secondreflection of the second pulse are each transmitted through the downholefluid. Wave properties may include travel time and amplitude.

For example, methods may include using two transducers and two pairs ofsymmetrically positioned reflectors having an offset distance foraccurate measurement of acoustic velocity, impedance, and attenuationcoefficient in borehole fluid under downhole conditions. The acousticimpedance in the fluid is determined from the reflected signalamplitudes of the first and the second reflector pair of the differentimpedance materials. The method is self-calibrating. That is, itself-corrects for the transducer sensitivity variation, beam spreading,and fluid attenuation effects in the acoustic impedance determination.

In FIG. 1, the device 100 comprises an acoustic assembly 110. Theacoustic assembly 110 comprises two ultrasound transducers 102, 112, andeach transducer is paired with two reflectors. The reflectors areconfigured to return the signal to the corresponding transducer formeasurement, although separate transmitting and receiving transducerscould also be employed. The transducers generate information responsiveto the returning acoustic reflection. The acoustic assembly 110 isconfigured such that a pulse from each transducer will reflect from anacoustically reflective surface of each reflector and return fordetection at the transducer. It may be beneficial in some applicationsfor the transducers to be of the same design and configuration. Thetransducers and reflectors, as well as the volume between, are immersedin the downhole fluid. The assembly may be one large fluid cell, or maybe separated with each transducer in a separate fluid cell, as long asthe fluid is substantially the same in each cell.

FIG. 2 shows another device in accordance with embodiments of thepresent disclosure. The device 100′ comprises an acoustic assembly 110′.The acoustic assembly 110′ comprises two ultrasound transducers 202,212, and each transducer is paired with two acoustically reflectingsurfaces. However, the transducers 202, 212 are positioned to operate inopposite directions, at normal incident angle, each facing symmetricallylocated dual reflectors with standoff L_(N) and offset ΔL.

Returning to FIG. 1, reflector 103 has an acoustically reflectivesurface 106, and reflector 104 has an acoustically reflective surface108. The reflectors 103, 104 are generally positioned some distance fromthe transducer 102 and adjacent the operative axis of the transducer102. The reflectors 103, 104 are positioned such that reflectivesurfaces 106, 108 face the transducer 102. The reflective surfaces 106,108 are positioned at staggered standoff distance from the transducer,such that surface 106 is a first distance (L_(N1)) from the transducer102 and surface 108 is a second distance (LF1) from the transducer 102greater than the first distance by an offset, ΔL₁. Thus, reflector 103may be referred to as the near reflector for transducer 102 andreflector 104 may be referred to as the far reflector.

Similarly, for the second transducer 112, reflector 113 has anacoustically reflective surface 116, and reflector 114 has anacoustically reflective surface 118. The reflectors 113, 114 aregenerally positioned some distance from the transducer 112 and adjacentthe operative axis of the transducer 112. The reflectors 113, 114 arepositioned such that reflective surfaces 116, 118 face the transducer112. The reflective surfaces 116, 118 are positioned at staggeredstandoff distances from the transducer, such that surface 116 is a firstdistance (L_(N2)) from the transducer 112 and surface 118 is a seconddistance (L_(F2)) from the transducer 112 greater than the firstdistance by an offset, ΔL₂. Thus, reflector 113 may be referred to asthe near reflector for transducer 112 and reflector 114 may be referredto as the far reflector. In some embodiments, L_(N1) may be equal toL_(N2) and/or L_(F1) may be equal to L_(F2).

The first transducer 102 emits ultrasonic waves (e.g., at a frequency of250-350 kHz), at normal incidence, to the first two reflectors 103, 104(1N, 1F) which are of the same high-impedance material and placedsymmetrically relative to the transducer beam center axis with an offsetdistance. Short-pulse, wide band transmitters may be beneficial. Thereflected acoustic waveform is received by the first transducer, and theechoes from the near reflector 103 and the far reflector 104 aredetected, and their signal amplitudes (A_(1N), A_(1F)) and their traveltimes, are measured. Near and far target separation may be needed forgood echo separation. Reflector thickness may be chosen to limitresonance excited by the pulse. Some implementations may include anaxial target separation gap for one or both targets.

The second transducer 112 emits ultrasonic waves, at normal incidence,to the second two reflector pair 113, 114 (2N, 2F) that aresymmetrically placed relative to the transducer beam center axis with anoffset distance. For the second pair the near reflector 113 (2N) may bea lower acoustic impedance material while the far target 114 (2F) is thesame high-impedance material as the first reflector pair 103, 104.Similarly, the reflected waveform from the second transducer isreceived, and the echoes from the near reflector 113 and the farreflector 114 are detected, and their signal amplitudes (A_(2N), A_(2F))and their travel times, are measured.

A downhole signal processor is used to multiply and normalize amplitudevalues, which is used to calculate the fluid acoustic impedance as shownbelow. The fluid attenuation coefficient can be determined from theratio of the signal amplitudes from the near 1N and the far reflector 1Fof the high-impedance pair. The sound velocity maybe determined from thedifference in the signal travel times and the constant offset.

The ultrasonic wave emitted from each transducer will be attenuated inthe fluid, and partially reflected from the first near target, andfurther attenuated and partially reflected from the second target. Thetargets may be positioned symmetrically and at a normal angle to thetransducer center axis. The acoustic main beam coverage for the near andfor the far reflector may be slightly different from beam spreading foreach. On the received waveform the reflected signals will separate intotwo signals given the offset of the two reflectors—one from the nearreflector and the other from the far reflector.

The proposed method of using dual-transducer, dual-target with offset,allows effective self-calibration of the above effects, as shown below.Also, the proposed method uses fixed reflectors and no movable parts.Moreover, the contributions from the fluid attenuation and from theimpedance mismatch at fluid-target interface are essentially separatedfrom each other, using the suggested method.

Referring to FIG. 1, the echo amplitudes from the near and the farreflectors of the first pair, due to the first transducer, A_(1N),A_(1F), and the echo amplitudes from the near and the far reflector ofthe second pair, due to the second transducer, A_(2N), A_(2F), are givenbelow:

A _(1N) =P ₀₁ B _(1N) G _(1N) e ^(−2αL) ^(N) R _(m,1N)  (1)

A _(1F) =P ₀₁ B _(1F) G _(1F) e ^(−2αL) ^(F) R _(m,1F)  (2)

A _(2N) =P ₀₂ B _(2N) G _(2N) e ^(−2αL) ^(N) R _(m,2N)  (3)

A _(2F) =P ₀₂ B _(2F) G _(2F) e ^(−2αL) ^(F) R _(m,2F)  (4)

In the above, P₀₁ and P₀₂ are the transmitted signal amplitudes(sensitivity factors) of transducer 102 and transducer 112; a is thefluid attenuation coefficient. The two transducers are of the samedesign and configurations, and substantially similar frequency andpulse-echo signal characteristics. B_(1N), B_(1F), B_(2N), and B_(2F)are the beam spreading factors, while G_(1N), G_(1F), G_(2N), G_(2F),are the geometric factors, of the near and the far targets for thetransducers. R_(m,1N), R_(m,1F), R_(m,2N), and R_(m,2F) are the acousticpressure amplitude reflection coefficients at the near and the farreflectors for transducer 102 and transducer 112, respectively. Becauseof the same design and configurations of the two transducers, and of thesymmetric positioning of the near and far targets relative to thetransducer center beam axis, the beam spreading factors B_(1N)=B_(2N),B_(1F)=B_(2F). Also due to the symmetry, the beam geometric factorsG_(1N)=G_(2N); G_(1F)=G_(2F).

The two reflectors corresponding to the first transmitter may be of thesame material, preferably a high acoustic impedance material.High-impedance materials are materials with an acoustic impedance of 25MRayls or more. In some applications, use of a strong reflector isdesirable. Strong reflectors are high-impedance materials with anacoustic impedance of 40 MRayls or more, such as stainless steel, carbonsteel, Inconel, titanium, or tungsten (having acoustic impedancesranging from 46 to 109 MRayls). As shown, this allows calculation of theecho travel time delay and ratio of echo amplitude, enabling thecalculation of sound speed in the fluid (c) and attenuation coefficient(a). However, the reflectors corresponding to the first transmitter mayalso be composed of different materials having an impedance contrast.

In the second cell the near reflector preferably may be a lower acousticimpedance (relatively acoustically damping) material. Lower impedancematerials are materials with an acoustic impedance of 15 MRayls or less.In some applications, use of a weak reflector is desirable. Weakreflectors are lower impedance materials with an acoustic impedance of5-10 MRayls, such as thermoplastics, epoxy, composite, or magnesium(having acoustic impedances ranging from 6 to 10 MRayls). The farreflector is of the same high-impedance material as the first cell. Thisallows direct calculation of fluid acoustic impedance (Z_(m)) from echoamplitude ratios, as shown below. The near or the far target of thesecond pair, does not have to be the same material as either the near orthe far of the first pair, but may be.

$\begin{matrix}{R_{m,{1N}} = {R_{m,{1F}} = {R_{m,{2F}} = \frac{Z_{2F} - Z_{m}}{Z_{2F} + Z_{m}}}}} & (5)\end{matrix}$ $\begin{matrix}{R_{m,{2N}} = \frac{Z_{2N} - Z_{m}}{Z_{2N} + Z_{m}}} & (6)\end{matrix}$

where, Z_(2N) and Z_(2F) are the acoustic impedances of the near and thefar reflector, and Z_(m) is the acoustic impedance of the borehole fluidto be determined. Re-arranging the equations (1)-(4), and using thecross-product ratio (A_(1N) A_(2F))/(A_(1F)A_(2N)) of the measuredsignal amplitudes, the transducer sensitivity factors, the beamspreading factors, the geometric factors, and the attenuation terms areall cancelled out, thus resulting in the equation:

$\begin{matrix}{\frac{A_{1N}A_{2F}}{A_{2N}A_{1F}} = {( \frac{Z_{2F} - Z_{m}}{Z_{2F} + Z_{m}} )/( \frac{Z_{2N} - Z_{m}}{Z_{2N} + Z_{m}} )}} & (7)\end{matrix}$

Defining C=(A_(1N)A_(2F))/(A_(1F)A_(2N)), the fluid impedance Z_(m) canbe directly solved from the measured echo amplitude ratio C, the knownacoustic impedances of the near target (low-impedance), Z_(2N), and ofthe far (high-impedance) reflectors, Z_(2F), (unit in MRayls).

$\begin{matrix}{Z_{m} = \frac{{- b} + \sqrt{b^{2} - {4{ac}}}}{2a}} & (8)\end{matrix}$ where a = 1 − C b = (1 + C)(Z_(2N) − Z_(2F))c = −(1 − C)Z_(2N)Z_(2F).

Equation (7) and (8) may be replaced with the more general formulation,as shown below, if the first pair of reflectors are not made of the samematerial.

Signal processing and steps may be used, i.e., signal gating, FFTprocessing, enveloping (or rectified) signal conversion from raw signal,noise filtering, detecting travel time and peaks for the near and thefar targets, and calculating fluid acoustic impedance, sound velocity,and attenuation coefficient, may be achieved using a downhole controllerand processor.

Use of wideband transducer (e.g., 6-dB bandwidth 60% or higher, atcenter frequency 250 kHz) capable of generating and receivingshort-pulse broad-band signal may be preferable. Symmetrical positioningof the near and the far targets (the two reflectors are of equal area),relative to the transducer beam axis, may be preferred for substantiallyequal beam coverage. In some implementations, it is desirable to usereflectors with a diameter approximately 20 percent larger than thetransducer diameter.

FIGS. 4A-4D show beam modeling resulting in accordance with embodimentsof the present disclosure. The modeling is based on a 250-kHzrectangular transducer of 34 mm tall and 12 mm wide. For thistransducer, results showed that the dominant transmit-receive pressurefield area, at 40 mm standoff, is about 30 mm in elevation and about 30mm in the lateral direction. Therefore, for that transducer, each targetreflector is preferably 5-10 mm taller and about 20-30 mm wider thanthose of the transducer. At 250 kHz (65% 6-dB bandwidth), a suitablestandoff would be 1.0-2.0 inches for the typical water-based andoil-based drilling fluid with attenuation coefficients up to 5-6 dB/cmat 250 kHz. The preferred offset between the two reflectors may be from0.50 to 1.0 inches. To minimize the reverberation ringing of the nearreflector and its interference to the far reflector signal, the lengthof the high-impedance reflectors, for example, stainless steel, may beless than 0.35 inches, or thicker than 0.70 inches. The length of thelow-impedance reflector may be 0.5-1.0 inches long. The near and the farreflectors may be separated apart, or may be a thin joint filled withdamping materials to reduce the lateral noise and boundary effects.

The attenuation coefficient in the fluid may be determined from themeasured signal amplitudes from the near and the far reflectors and thenear-far reflector offset ΔL, neglecting the beam spreading andgeometric effects (in unit of dB/cm):

$\begin{matrix}{\alpha = {\frac{10}{\Delta L}\log_{10}\frac{A_{1N}}{A_{1F}}}} & (9)\end{matrix}$

Alternatively, to account for frequency effect, the mud attenuation at afrequency can be calculated using (9), from the FFT spectrum magnitudesat the frequency of the near and far reflector signals.

For more accurate fluid attenuation measurement, the beam and geometriceffects can be pre-calibrated, i.e., in water, using the firsttransducer cell of the two same high-impedance reflectors. Then thefluid attenuation coefficient may be calculated from the signalamplitude ratio in an unknown fluid, and from the signal ratio measuredin the water reference (in unit dB/cm):

$\begin{matrix}{\alpha = {\frac{10}{\Delta L}\log_{10}\frac{( {A_{1N}/A_{1F}} )_{fluid}}{( {A_{1F}/A_{1F}} )_{water}}}} & (10)\end{matrix}$

The sound speed in the fluid, c, may be directly calculated from ΔT, thedifference in time delay of the near and the far reflector signals, andΔL, the known offset, c=2ΔL/ΔT, and is thus self-corrected forelectronic delay variations and transducer internal travel timevariations. The waveform may be filtered and rectified. The near and thefar reflection signals may be detected using a peak (or envelope peak)search. To increase the robustness and accuracy, the far reflectorsignal may be delay gated, and peak (or envelope peak) detection may beused to bypass the noise and near or tail interference from the nearreflection signal.

Additionally, as long as the material properties (e.g., acousticimpedance) of the four targets (the near and the far reflectorsassociated with the first transmitter; and the near and the farreflectors associated with the second transmitter), are known (orpre-determined in lab under high temperature and high pressureconditions), the fluid impedance Z_(m) can be solved from measuredamplitude ratio C, and a reflection coefficient of each target, in amore general equation:

C=[A _(1N) *A _(2F)/(A _(2N) *A _(1F))]=(R _(m,1N) *R _(m,2F))/(R_(m,2N) *R _(m,1F))  (11)

where R_(m1,N), R_(m,1F), R_(m,2N), and R_(m,2F) are the pressureamplitude reflection coefficients of the near of the first pair, the farof the first pair, the near of the second pair, and the far of thesecond pair, respectively. Proper use of this equation may involvecanceling the geometric and beam spreading factors. To satisfy thiscondition, the two transducers are preferably of the same design, havingapproximately similar size and operating at similar frequencies(although, the sensitivity may be different), and using similarstandoffs for the two near targets and for the two far targets.

Returning to FIG. 2, the device 100′ comprises an acoustic assembly110′. The acoustic assembly 110′ comprises two ultrasound transducers202, 212, and each transducer is paired with two acoustically reflectingsurfaces. However, the transducers 202, 212 are positioned to operate inopposite directions, at normal incident angle, each facing symmetricallylocated dual reflectors with standoff L_(N) and offset ΔL. One of thenear reflectors (2N) may be a lower impedance material and the otherthree reflectors are of same high-impedance material. To mitigateeffects of signal attenuation, one of the near reflectors (2N) may be alow-impedance material. Alternatively, the far reflector (2F) may be alow-impedance material while the near target (2N) is the samehigh-impedance material as 1N and 1F.

Reflector 203 has an acoustically reflective surface 206, and reflector204 has an acoustically reflective surface 208. The reflectors 203, 204are generally positioned some distance from the transducer 202 andadjacent the operative axis of the transducer 202. The reflectors 203,204 are positioned such that reflective surfaces 206, 208 face thetransducer 202. The reflective surfaces 206, 208 are positioned atstaggered standoff distance from the transducer, such that surface 106is a first distance (L_(N1)) from the transducer 102 and surface 108 isa second distance (L_(F1)) from the transducer 102 greater than thefirst distance by an offset, ΔL₁. Thus, reflector 103 may be referred toas the near reflector for transducer 102 and reflector 104 may bereferred to as the far reflector.

Similarly, for the second transducer 212, reflector 213 has anacoustically reflective surface 216, and reflector 214 has anacoustically reflective surface 218. The reflectors 213, 214 aregenerally positioned some distance from the transducer 212 and adjacentthe operative axis of the transducer 212. The reflectors 213, 214 arepositioned such that reflective surfaces 216, 218 face the transducer212. The reflective surfaces 216, 218 are positioned at staggeredstandoff distances from the transducer, such that surface 216 is a firstdistance (L_(N2)) from the transducer 212 and surface 218 is a seconddistance (L_(F2)) from the transducer 212 greater than the firstdistance by an offset, ΔL₂. Thus, reflector 213 may be referred to asthe near reflector for transducer 212 and reflector 214 may be referredto as the far reflector. L_(N1) may be equal to L_(N2) and/or L_(F1) maybe equal to L_(F2). In alternative embodiments, adjacent reflectorsformed of the same material (e.g., 203, 213) may be implemented as asingle reflector with increased dimensions having two acousticallyreflecting surfaces.

FIGS. 3A-3C show another device in accordance with embodiments of thepresent disclosure. The device 300 comprises an acoustic assembly 310with a rotating transducer 312, so that the transducer and the system ofreflectors rotate with respect to one another. For example, transducer312 may be mounted on a rotating transducer sub or the like. Thetransducer 312 acts as both transmitter and receiver, although otherembodiments may feature other types of combined transmitter/receiver, aseparate transmitter and receiver, multiple transmitters and/orreceivers, multiple transducers, and so on. The acoustic pulse may beultrasonic. Alternative embodiments may include more or fewerreflectors. The transducer 312 is configured to rotate about an axis ofthe assembly 314, and when oriented toward each respective reflector,transmit an acoustic pulse and receive a reflection of that pulse fromthe particular reflector.

Each of the reflectors 303, 304, 313 includes an acoustically reflectivesurface 306, 308, 316, respectively. The first acoustically reflectivesurface 316, the second acoustically reflective surface 306, and thethird acoustically reflective surface 308 are azimuthally distributedabout the axis, such that each of the first reflection, the secondreflection, and the third reflection each return to the acousticreceiver from a different azimuth with respect to the axis 314. Thereflectors may be circumferentially positioned (e.g., mounted)—that is,positioned proximate a circumference of the tool cross-section.

The reflectors 303, 304, 313 are generally positioned some distance fromthe face 301 of the transducer 312 during reception (and/ortransmission) of the reflection. Assembly 310 is configured such thatreflective surfaces 306, 308, 316, respectively return a reflection ofthe respective transmitted acoustic pulse to the transducer face 301.

FIGS. 3A-3C show the transducer 312 in three different orientationscorresponding to three different points of rotation. The transducerrotates from the first orientation (facing a low-impedance reflector) inFIG. 3A to face (at approximately normal incidence) a high-impedancereflector (at the same standoff as the first reflector). From the signalamplitudes of the low- and high-impedance reflectors, the fluidimpedance can be determined. Additionally, the transducer may rotate toa third orientation and face (at approximately normal incidence) a thirdreflector, which is of the same material as the second one, but at adifferent standoff. From the signal amplitudes and time delays of thesecond and the third reflector, fluid attenuation coefficient andvelocity may be determined.

At the first position (FIG. 3A) the signal amplitude from the firstreflection may be expressed as:

$\begin{matrix}{A_{1} = {P_{1}B_{1}{{e^{- 2L_{1}\alpha}( \frac{Z_{1} - Z_{m}}{Z_{1} + Z_{m}} )}.}}} & (12)\end{matrix}$

At the second position (FIG. 3B) the signal amplitude from the secondreflection may be expressed as:

$\begin{matrix}{A_{2} = {P_{1}B_{1}{{e^{- 2L_{1}\alpha}( \frac{Z_{2} - Z_{m}}{Z_{2} + Z_{m}} )}.}}} & (13)\end{matrix}$

Fluid impedance Z_(m), is solved from the ratio of signal Amplitudes,C=A₁/A₂, and Z₁ and Z₂, cancelling transducer sensitivity factor P₀₁,beam spreading factor B₁, and attenuation factor e^(−2L) ¹ ^(α),

$\begin{matrix}\begin{matrix}{{Z_{m} = \frac{{- b^{\prime}} + \sqrt{b^{\prime 2} - {4a^{\prime}c^{\prime}}}}{2a^{\prime}}},} \\{{Where},{a^{\prime} = {1 - C}}} \\{b^{\prime} = {( {Z_{2} - Z_{1}} )( {1 + C} )}} \\{c^{\prime} = {- ( {1 - C} )Z_{1}Z_{2}}}\end{matrix} & (14)\end{matrix}$

At the first position (FIG. 3A) the signal amplitude from the firstreflection may be expressed as:

$\begin{matrix}{A_{3} = {P_{1}B_{3}{{e^{- 2L_{2}\alpha}( \frac{Z_{2} - Z_{m}}{Z_{2} + Z_{m}} )}.}}} & (15)\end{matrix}$

Fluid attenuation is given approximately (in dB/cm, L in cm), assumingB₁≈B3,

$\begin{matrix}{\alpha = {\frac{10}{L_{2} - L_{1}}\log_{10}{( \frac{A_{2}}{A_{3}} ).}}} & (16)\end{matrix}$

Fluid sound velocity from echo travel times from reflector 2 and 3,c=(L₂−L₁)/[2(T₃−T₂)].

In other implementations, only two reflectors may be used. Usingreflectors mounted at the same radial distance to the transducer and attwo azimuthal positions, if the first reflector is made of a materialwith a known high impedance and the second reflector is made of amaterial with a known low impedance, the fluid impedance may be directlysolved from the ratio of the received signal amplitudes of the tworeflectors. The effects of both the mud attenuation effect (at the samedistance) and transducer sensitivity (same transducer used) arecanceled. Using only two azimuthally mounted reflectors of the same highimpedance material with an axial offset, mud velocity and attenuationmay be directly determined.

Techniques of the present disclosure display several advantages.Accurate in-situ measurement of acoustic velocity, acoustic impedance,and attenuation coefficient of downhole fluids may be achieved by usingat least one downhole processor for detecting and analyzing travel timesand amplitudes of reflections from reflectors having properties with theadvantageous relationships as presented in the disclosure.

With respect to some embodiments, methods enable calibrated, in-situdetermination of fluid acoustic impedance from the cross-product ratioof the amplitudes of the four reflectors. Variations due to individualtransducer sensitivity, temperature and pressure effects, fluidattenuation effects, and beam spreading, are effectively mitigated. Moreaccurate sound velocity is measured using two constant offsets, ascompared to a conventional one standoff method, because the internaltravel time variations due to transducer variability and pressure andtemperature conditions, are effectively removed.

Test results in distilled water (Z_(m)=1.49 MRayls, 25 C) are shownbelow for the fluid impedance inversion model. Errors in estimatedimpedance (Z_(m) inverted vs. Z_(m) known, in MRayls) using the methodwere less than 3 percent.

TABLE 1 A_(1N) A_(1F) A_(2N) A_(2F) Z_(1N) Z_(1F) Z_(2N) Z_(2F) Z_(m)Z_(m) (V) (V) (V) (V) C (MRay1) (MRay1) (MRay1) (MRay1) (Inverted)(Known) Dual sst- 1.444 1.454 1.4813 0.55 0.369 46 46 46 3.01 1.457 1.49Teflon, Both sides covered) Dual sst-Teflon, 1.485 1.498 1.4893 0.54180.361 46 46 46 3.01 1.489 1.49 No covered; Dual sst-Torlon, 1.485 1.4981.5109 0.6991 0.459 46 46 46 3.783 1.510 1.49 No covered;

As a result of more accurate borehole fluid velocity, standoff andcaliper measurements thus determined are more accurate than conventionalone-standoff or indirect sound velocity estimate methods. Theattenuation coefficient in the fluid may be measured directly from thesignal (or FFT spectrum magnitude). Due to fixed near-target standoffand offset, beam spreading effects can be pre-calibrated or correctedwith less error, thus allowing more accurate attenuation coefficientdetermination. No movable parts are used, and the mechanical setup istechnically undemanding.

FIGS. 4E-4G show an example measured waveform illustrating results ofemploying techniques of the present disclosure. In FIG. 4E, the waveformshows the split echoes from two stainless steel 304 plate reflectors indistilled water. The two plates were placed symmetrically relative tothe center axis of an oval 250-kHz transducer (0.75″ wide and 1.625″ inheight). The near plate is 0.625″ thickness and placed at 2.0″ standoff.The far plate is 0.375″ thickness with an offset of 0.625″ to the neartarget. The echo amplitudes from the two reflectors were very close,indicating small beam spreading and boundary effects. FIG. 4F shows thesplit signals from near steel reflector and a far Teflon plate (acousticimpedance Z=3.01 MRayls). It is apparent that when the far stainlesssteel reflector is replaced with a low-impedance target, the signalamplitude is lowered.

FIG. 4G shows the signals from the near steel reflector and a far Torlon4203 plate (Z=3.78 MRayls). The echo amplitude from Torlon is higherthan from Teflon. The acoustic impedance in the fluid (distilled water)was determined from the measured echo amplitudes according to Eq. (8),with relative errors of −2.19 percent (with Teflon, up/low sidescovered), −0.06 percent (using Teflon no cover) and 1.32 percent (usingTorlon no cover), comparing to the known impedance of 1.49 MRayls inwater.

Measurements may take place on an outer surface of the tool, such as adrill string, such that a sample chamber or other cavity is notrequired. Thus, properties of the downhole fluid may be determinedin-situ in the borehole, so that the fluid is unchanged by sampling ortransportation processes. In other embodiments, the device may beconfigured for use in a sample chamber. The reflection-only aspects ofthe present disclosure enable use in size restrictive applications andallow use of higher acoustic frequencies.

In some implementations, the disclosed embodiments may be used as partof a drilling system. An example drilling system for use in conjunctionwith MWD and LWT is illustrated herein.

FIG. 5 is a schematic diagram of an exemplary drilling system 500according to one embodiment of the disclosure. FIG. 5 schematicallyillustrates a drilling system 500 configured to acquire information fordownhole fluid analysis in a borehole intersecting a formation using atest apparatus; drilling system 500 includes a drill string 520 thatincludes a bottomhole assembly (BHA) 590 conveyed in a borehole 526. Thedrilling system 500 includes a conventional derrick 511 erected on aplatform or floor 512 which supports a rotary table 514 that is rotatedby a prime mover, such as an electric motor (not shown), at a desiredrotational speed. A tubing (such as jointed drill pipe 522), having thedrilling assembly 590, attached at its bottom end extends from thesurface to the bottom 551 of the borehole 526. A drill bit 550, attachedto drilling assembly 590, disintegrates the geological formations whenit is rotated to drill the borehole 526. The drill string 520 is coupledto a drawworks 530 via a Kelly joint 521, swivel 528 and line 529through a pulley. Drawworks 530 is operated to control the weight on bit(“WOB”). The drill string 520 may be rotated by a top drive (not shown)instead of by the prime mover and the rotary table 514. Alternatively, acoiled-tubing may be used as the tubing 522. A tubing injector 514 a maybe used to convey the coiled-tubing having the drilling assemblyattached to its bottom end. The operations of the drawworks 530 and thetubing injector 514 a are known in the art and are thus not described indetail herein.

A suitable drilling fluid 531 (also referred to as the “mud”) from asource 532 thereof, such as a mud pit, may be circulated under pressurethrough the drill string 520 by a mud pump 534. The drilling fluid 531passes from the mud pump 534 into the drill string 520 via a desurger536 and the fluid line 538. The drilling fluid 531 a from the drillingtubular discharges at the borehole bottom 551 through openings in thedrill bit 550. The returning drilling fluid 531 b circulates upholethrough the annular space 527 between the drill string 520 and theborehole 526 and returns to the mud pit 532 via a return line 535 anddrill cutting screen 585 that removes the drill cuttings 586 from thereturning drilling fluid 531 b. A sensor S1 in line 538 providesinformation about the fluid flow rate. A surface torque sensor S2 and asensor S3 associated with the drill string 520 respectively provideinformation about the torque and the rotational speed of the drillstring 520. Tubing injection speed is determined from the sensor S5,while the sensor S6 provides the hook load of the drill string 520.

Well control system 547 is placed at the top end of the borehole 526.The well control system 547 includes a surface blow-out-preventer (BOP)stack 515 and a surface choke 549 in communication with a wellboreannulus 527. The surface choke 549 can control the flow of fluid out ofthe borehole 526 to provide a back pressure as needed to control thewell.

In some applications, the drill bit 550 is rotated by only rotating thedrill pipe 522. However, in many other applications, a downhole motor555 (mud motor) disposed in the BHA 590 also rotates the drill bit 550.The rate of penetration (ROP) for a given BHA largely depends on the WOBor the thrust force on the drill bit 550 and its rotational speed.

A surface control unit or controller 540 receives signals from thedownhole sensors and devices via a sensor 543 placed in the fluid line538 and signals from sensors S1-S6 and other sensors used in the system500 and processes such signals according to programmed instructionsprovided to the surface control unit 540. The surface control unit 540displays desired drilling parameters and other information on adisplay/monitor 541 that is utilized by an operator to control thedrilling operations. The surface control unit 540 may be acomputer-based unit that may include a processor 542 (such as amicroprocessor), a storage device 544, such as a solid-state memory,tape or hard disc, and one or more computer programs 546 in the storagedevice 544 that are accessible to the processor 542 for executinginstructions contained in such programs. The surface control unit 540may further communicate with a remote control unit 548. The surfacecontrol unit 540 may process data relating to the drilling operations,data from the sensors and devices on the surface, data received fromdownhole, and may control one or more operations of the downhole andsurface devices. The data may be transmitted in analog or digital form.

The BHA 590 may also contain formation evaluation sensors or devices(also referred to as measurement-while-drilling (“MWD”) orlogging-while-drilling (“LWD”) sensors) determining resistivity,density, porosity, permeability, acoustic properties, nuclear-magneticresonance properties, formation pressures, properties or characteristicsof the fluids downhole and other desired properties of the formation 595surrounding the BHA 590. Such sensors are generally known in the art andfor convenience are generally denoted herein by numeral 565. The BHA 590may further include a variety of other sensors and devices 559 fordetermining one or more properties of the BHA 590 (such as vibration,bending moment, acceleration, oscillations, whirl, stick-slip, etc.),drilling operating parameters (such as weight-on-bit, fluid flow rate,pressure, temperature, rate of penetration, azimuth, tool face, drillbit rotation, etc.).

The BHA 590 may include a steering apparatus or tool 558 for steeringthe drill bit 550 along a desired drilling path. In one aspect, thesteering apparatus may include a steering unit 560, having a number offorce application members 561 a-561 n. The force application members maybe mounted directly on the drill string, or they may be at leastpartially integrated into the drilling motor. In another aspect, theforce application members may be mounted on a sleeve, which is rotatableabout the center axis of the drill string. The force application membersmay be activated using electro-mechanical, electro-hydraulic ormud-hydraulic actuators. In yet another embodiment the steeringapparatus may include a steering unit 558 having a bent sub and a firststeering device 558 a to orient the bent sub in the wellbore and thesecond steering device 558 b to maintain the bent sub along a selecteddrilling direction. The steering unit 558, 560 may include near-bitinclinometers and magnetometers.

The drilling system 500 may include sensors, circuitry and processingsoftware and algorithms for providing information about desired drillingparameters relating to the BHA, drill string, the drill bit and downholeequipment such as a drilling motor, steering unit, thrusters, etc. Manycurrent drilling systems, especially for drilling highly deviated andhorizontal wellbores, utilize coiled-tubing for conveying the drillingassembly downhole. In such applications a thruster may be deployed inthe drill string 590 to provide the required force on the drill bit.

Exemplary sensors for determining drilling parameters include, but arenot limited to drill bit sensors, an RPM sensor, a weight on bit sensor,sensors for measuring mud motor parameters (e.g., mud motor statortemperature, differential pressure across a mud motor, and fluid flowrate through a mud motor), and sensors for measuring acceleration,vibration, whirl, radial displacement, stick-slip, torque, shock,vibration, strain, stress, bending moment, bit bounce, axial thrust,friction, backward rotation, BHA buckling, and radial thrust. Sensorsdistributed along the drill string can measure physical quantities suchas drill string acceleration and strain, internal pressures in the drillstring bore, external pressure in the annulus, vibration, temperature,electrical and magnetic field intensities inside the drill string, boreof the drill string, etc. Suitable systems for making dynamic downholemeasurements include COPILOT, a downhole measurement system,manufactured by BAKER HUGHES INCORPORATED.

The drilling system 500 can include one or more downhole processors at asuitable location such as 593 on the BHA 590. The processor(s) can be amicroprocessor that uses a computer program implemented on a suitablenon-transitory computer-readable medium that enables the processor toperform the control and processing. The non-transitory computer-readablemedium may include one or more ROMs, EPROMs, EAROMs, EEPROMs, FlashMemories, RAMs, Hard Drives and/or Optical disks. Other equipment suchas power and data buses, power supplies, and the like will be apparentto one skilled in the art. In one embodiment, the MWD system utilizesmud pulse telemetry to communicate data from a downhole location to thesurface while drilling operations take place.

While a drill string 520 is shown as a carrier (conveyance device) forsensors 565, it should be understood that embodiments of the presentdisclosure may be used in connection with tools conveyed via rigid (e.g.jointed tubular or coiled tubing) as well as non-rigid (e. g. wireline,slickline, e-line, etc.) conveyance systems. The drilling system 500 mayinclude a bottomhole assembly and/or sensors and equipment forimplementation of embodiments of the present disclosure on either adrill string or a wireline.

A point of novelty of the system illustrated in FIG. 5 is that thesurface processor 542 and/or the downhole processor 593 are configuredto perform certain methods (discussed below) that are not in the priorart. Surface processor 542 or downhole processor 593 may be configuredto control components of the drilling system 500. Surface processor 542or downhole processor 593 may be configured to control sensors describedabove and to estimate a parameter of interest according to methodsdescribed herein. Control of these devices, and of the various processesof the drilling system generally, may be carried out in a completelyautomated fashion or through interaction with personnel vianotifications, graphical representations, user interfaces and the like.Reference information accessible to the processor may also be used.

More specifically, drill string 520 (or BHA 590) may include anapparatus for estimating one or more parameters of the downhole fluid.For convenience, such apparatus may be denoted by numeral 559 or 565,and may comprise device 100 or other devices or tools in accordance withembodiments of the present disclosure. In some general embodiments,surface processor 542, downhole processor 593, or other processors (e.g.remote processors) may be configured to use the apparatus to produceinformation indicative of the downhole fluid, such as, for example,drilling fluid. One of the processors may also be configured to estimatefrom the information a parameter of interest of the downhole fluid.

In some embodiments, drill string 520 may include an acoustic loggingapparatus configured for evaluating the cement bond occupying theannular space between the casing and the borehole wall, as described ingreater detail below with reference to FIG. 6. For convenience, suchapparatus may be denoted by numeral 559 or 565. In some generalembodiments, surface processor 542, downhole processor 593, or otherprocessors (e.g. remote processors) may be configured to use theacoustic logging apparatus to produce information indicative of theproperties of the cement bond.

In some embodiments, processors may include electromechanical and/orelectrical circuitry configured to control one or more components of thetool apparatus. In other embodiments, processors may use algorithms andprogramming to receive information and control operation of theapparatus. Therefore, processors may include an information processorthat is in data communication with a data storage medium and a processormemory. The data storage medium may be any standard computer datastorage device, such as a USB drive, memory stick, hard disk, removableRAM, EPROMs, EAROMs, flash memories and optical disks or other commonlyused memory storage system known to one of ordinary skill in the artincluding Internet based storage. The data storage medium may store oneor more programs that when executed causes information processor toexecute the disclosed method(s). Herein, “information” may include rawdata, processed data, analog signals, and digital signals.

As described above, carriers such as coiled tubing, slickline, e-line,wireline, and so one may be used in connection with the techniquesdisclosed herein. In some embodiments, the sensor described herein maybe implemented as a sampling and measuring instrument, such as, forexample, one employing a probe. Specific configuration of the componentswith respect to one another may vary.

FIG. 6 illustrates an acoustic logging tool in accordance withembodiments of the present disclosure. The tool 610 is configured to beconveyed in a borehole intersecting a formation 480. The borehole wall640 is lined with casing 630 filled with a downhole fluid 660, such as,for example, drilling fluid. Cement 620 fills the annulus between theborehole wall 640 and the casing 630. In one illustrative embodiment,the tool 610 may contain a sensor unit 650, including, for example, oneor more acoustic transmitters and receivers (e.g., transducers),configured for evaluation of the cement bond existing between the systemof the casing 630, the borehole wall 640, and the cement 620 accordingto known techniques. For example, electronics in the tool 610, at thesurface, and/or elsewhere in system 601 (e.g., at least one processor)may be configured to use acoustic measurements to determine propertiesof the cement bond using known techniques, such as, for example,analysis of casing resonance.

The system 601 may include a conventional derrick 670. A conveyancedevice (carrier 615) which may be rigid or non-rigid, may be configuredto convey the downhole tool 610 into wellbore 640 in proximity toformation 680. The carrier 615 may be a drill string, coiled tubing, aslickline, an e-line, a wireline, etc. Downhole tool 610 may be coupledor combined with additional tools (e.g., some or all the informationprocessing system of FIG. 5). Thus, depending on the configuration, thetool 610 may be used during drilling and/or after the wellbore(borehole) 640 has been formed. While a land system is shown, theteachings of the present disclosure may also be utilized in offshore orsubsea applications. The carrier 615 may include embedded conductors forpower and/or data for providing signal and/or power communicationbetween the surface and downhole equipment. The carrier 615 may includea bottom hole assembly, which may include a drilling motor for rotatinga drill bit.

FIG. 7A illustrates variations in acoustic impedance with echo amplituderatio for weak reflectors of various impedances. FIG. 7B illustratesvariations in acoustic impedance with echo amplitude ratio for strongreflectors of various impedances. Selection of lower impedance targetsmay be carried out in dependence upon a preliminary (or a priori)indication of fluid impedance. Common borehole fluid impedance is 0.8 to3.5 MRayls. Fluid impedance may be determined from four echo amplitudevalues:

[(A _(2N) /A _(1N))]/[(A _(2F))/(A _(1F))]=[(Z _(x) −Z _(m))/(Z _(x) +Z_(m))]/[(Z _(sst) −Z _(m))/(Z _(sst) +Z _(m))].   (17)

FIG. 7C illustrates effects of transducer sensitivity differences. Thesedifferences may be corrected. Sensitivity ratios of the transmitters maybe determined from the ratio of the echo amplitudes from the two farreflectors:

P ₀₂ /P ₀₁ =A _(2F) /A _(1F).   (18)

FIG. 8A shows a flow chart of a method 800 for determining an acousticparameter of a downhole fluid using an acoustic assembly comprising aplurality of acoustic reflectors each having at least one acousticallyreflective surface in accordance with embodiments of the presentdisclosure. Step 810 comprises transmitting pulses. Step 820 comprisesmeasuring values for at least one wave property measured for reflectionsof the plurality of pulses received at at least one acoustic receiver.Step 820 a comprises measuring a first value for a first reflectiontraveling a first known distance from a first acoustically reflectivesurface (ARS) having a first known acoustic impedance. Step 820 bcomprises measuring a second value for a second reflection traveling asecond known distance substantially the same as the first known distancefrom a second acoustically reflective surface having a second knownacoustic impedance substantially different than the first acousticimpedance. Step 820 c comprises measuring a third value for a thirdreflection traveling a third known distance substantially different fromeach of the first distance and the second distance from a thirdacoustically reflective surface having a third known acoustic impedancesubstantially the same as the second acoustic impedance. Step 830comprises estimating the acoustic parameter using the values.

FIG. 8B shows a flow chart of a method 850 for determining an acousticparameter of a downhole fluid using an acoustic assembly comprising aplurality of acoustic reflectors each having at least one acousticallyreflective surface in accordance with embodiments of the presentdisclosure. The method 850 may include using device 100 or the like. Inoptional step 860, an acoustic assembly 110 is conveyed into theborehole. For example, the acoustic assembly may be conveyed usingconveyance device (or carrier) 615. In optional step 870, at least oneacoustically reflective surface for each of the plurality of acousticreflectors is at least partially immersed in the downhole fluid.

Step 880 comprises transmitting a plurality of pulses. Step 880 may becarried out by transmitting a first pulse and a second pulse through thedownhole fluid which causes a first reflection of the first pulse from afirst acoustically reflective surface, a second reflection of the firstpulse from a second acoustically reflective surface, a first reflectionof the second pulse from a third acoustically reflective surface, and asecond reflection of the second pulse from the second acousticallyreflective surface. The first acoustically reflective surface mayinclude a portion of a first acoustic reflector having a first impedancevalue and the second acoustically reflective surface may comprise aportion of a second acoustic reflector having a second impedance valuesubstantially the same as the first impedance value. The thirdacoustically reflective surface may comprise a portion of a thirdacoustic reflector having a third impedance value and the fourthacoustically reflective surface may comprise a portion of a fourthacoustic reflector having a fourth impedance value substantiallydifferent than the third impedance value. The fourth impedance value maybe substantially the same as at least one of: i) the first impedancevalue, and ii) the second impedance value.

Alternatively, the first acoustically reflective surface may comprise aportion of a first acoustic reflector having a first impedance value andthe third acoustically reflective surface may comprise another portionof the first acoustic reflector having first impedance value.Alternatively, pulses may be transmitted in various azimuthal directionscorresponding with azimuthally arrayed reflectors as described above.

At step 885 reflections are received. Step 885 may comprise substeps ofreceiving at a first acoustic receiver (R1) the first reflection of thefirst pulse from the first acoustically reflective surface located afirst distance from the first acoustic receiver; receiving at the firstacoustic receiver (R1) the second reflection of the first pulse from thesecond acoustically reflective surface located a second distance fromthe first acoustic receiver different than the first distance; receivingat a second acoustic receiver (R2) the first reflection of the secondpulse from the third acoustically reflective surface located a thirddistance from the second acoustic receiver; receiving at the secondacoustic receiver (R2) the second reflection of the second pulse fromthe fourth acoustically reflective surface located a fourth distancefrom the second acoustic receiver different than the third distance.

Alternatively, step 885 may comprise measuring values for at least onewave property measured for reflections of the plurality of pulsesreceived at at least one acoustic receiver, including: a first value fora first reflection traveling a first known distance from a firstacoustically reflective surface having a first known acoustic impedance;a second value for a second reflection traveling a second known distancesubstantially the same as the first known distance from a secondacoustically reflective surface having a second known acoustic impedancesubstantially different than the first acoustic impedance; and a thirdvalue for a third reflection traveling a third known distancesubstantially different from each of the first distance and the seconddistance from a third acoustically reflective surface having a thirdknown acoustic impedance substantially the same as the second acousticimpedance.

Step 890 comprises estimating the acoustic parameter using a value forat least one wave property measured for each reflection. Step 840 may becarried out by estimating the acoustic parameter using a value for atleast one characteristic corresponding to each of the first reflectionof the first pulse, the second reflection of the first pulse, the firstreflection of the second pulse, and the second reflection of the secondpulse. Alternatively, the acoustic parameter may be determined using themeasured values of the reflections from the azimuthally arrayedreflectors. The at least one wave property may include at least one oftravel time and amplitude.

The term “carrier” (or “conveyance device”) as used above means anydevice, device component, combination of devices, media and/or memberthat may be used to convey, house, support or otherwise facilitate theuse of another device, device component, combination of devices, mediaand/or member. Exemplary non-limiting carriers include drill strings ofthe coiled tube type, of the jointed pipe type and any combination orportion thereof. Other carrier examples include casing pipes, wirelines,wireline sondes, slickline sondes, drop shots, downhole subs, BHA's,drill string inserts, modules, internal housings and substrate portionsthereof, self-propelled tractors. As used above, the term “sub” refersto any structure that is configured to partially enclose, completelyenclose, house, or support a device. The term “information” as usedabove includes any form of information (analog, digital, EM, printed,etc.). The term “processor” herein includes, but is not limited to, anydevice that transmits, receives, manipulates, converts, calculates,modulates, transposes, carries, stores or otherwise utilizesinformation. A processor refers to any circuitry performing the above,and may include a microprocessor, resident memory, and/or peripheralsfor executing programmed instructions, application specific integratedcircuits (ASICs), field programmable gate arrays (FPGAs), or any othercircuitry configured to execute logic to perform methods as describedherein. Fluid, as described herein, may refer to a liquid, a gas, amixture, and so on.

“Substantially different” as used herein means not substantially thesame. “Substantially the same,” or “substantially similar” as usedherein for a measured or estimated fluid parameter value means a valuewithin generally held range of common deviation, such as, for example, acommon statistical deviation for measurements of the same fluid (e.g.,within one standard deviation, within 2 percent, etc.), such as, forexample, due to noise. The term “substantially the same” as applied inthe context of independent parameters (such as distance and acousticimpedance) refers to values negating the determinative effects ofdifferences in properties of pulse reflections to estimate fluidparameters using the techniques herein, such that differences inresulting signal properties of acoustic reflections within a systemhaving corresponding independent parameter values are negligible.

The term “near real-time” as applied to methods of the presentdisclosure refers to an action performed while the instrument is stilldownhole, after the generation of the pulse reflection and prior tomovement of the tool a distance of 100 meters, 50 meters, 25 meters, 10meters, 1 meter, or less; and may be defined as estimation of theparameter of interest within 15 minutes of generating the pulsereflection, within 10 minutes of generation, within 5 minutes ofgeneration, within 3 minutes of generation, within 2 minutes ofgeneration, within 1 minute of generation, or less.

The term “in-situ” as applied herein to evaluating acoustical propertiesof downhole fluids refers to evaluation of the fluids in the borehole(and while exterior to the tool) prior to exposure to externalinfluences, e.g., fluid in an interval of the annulus between theborehole and the tool. By “substantially continuously,” it is meant atintervals of time sufficiently small so that granularity of measurementdoes not appreciably affect the accuracy of determination of a relatedproperty, examples of such an interval being, for example, less than 1minute, less than 10 seconds, less than 1 second, less than 100milliseconds, less than 10 milliseconds, less than 1 millisecond, and soon.

Non-limiting examples of downhole fluids include drilling fluids, returnfluids, formation fluids, production fluids containing one or morehydrocarbons, oils and solvents used in conjunction with downhole tools,water, brine, engineered fluids, and combinations thereof. The tool maycontain a formation test apparatus according to the present disclosure,which will be described in greater detail below.

As described above, acoustic parameters of the downhole fluid such asacoustic impedance may be used in making other measurements in theborehole and estimating further parameters of interest (e.g., cementacoustic impedance), borehole wall acoustic impedance, borehole fluididentification and characterization, formation fluid sampling analysis,drilling dynamic event monitoring (gas bubbles, kicks, cuttings, etc.),and borehole washout and fracture imaging. Method embodiments mayinclude conducting further operations in the earth formation independence upon such acoustic parameters and/or formation information(for example, standoff, borehole caliper and shape, formation densityand porosity (correction of gamma and neutron readings), formationacoustic compressional and shear slowness, et. al.), or upon modelscreated using ones of these. Further operations may include at least oneof: i) geosteering; ii) drilling additional boreholes in the formation;iii) performing additional measurements on the casing and/or theformation; iv) estimating additional parameters of the casing and/or theformation; v) installing equipment in the borehole; vi) evaluating theformation; vii) optimizing present or future development in theformation or in a similar formation; viii) optimizing present or futureexploration in the formation or in a similar formation; ix) drilling theborehole; and x) producing one or more hydrocarbons from the formation.

Estimated parameter values and/or models of the formation (or portionsthereof) may be stored (recorded) as information or visually depicted ona display. The visual depiction may include a two-dimensional (2D) orthree dimensional (3D) graphical depiction of values of the parameter ofinterest (although one-dimensional (1D) depictions may also be displayedin some applications). The values or model may be transmitted before orafter storage or display, such as, for example, being transmitted uphole(i.e., to the surface or to modules closer to the surface). For example,information may be transmitted to other downhole components, or to thesurface for storage, display, or further processing. Aspects of thepresent disclosure relate to modeling a volume of an earth formationusing the estimated parameter values, such as, for example, byassociating estimated parameter values with portions of the volume ofinterest to which they correspond, or by representing a boundary betweenareas of representative or statistically similar values along with theformation in a global coordinate system. Aspects include maintaining amodel comprising a representation of the earth formation stored asinformation including a representation of parameter values with respectto location, either as absolute values or variances thereof. The modelof the earth formation generated and maintained in aspects of thedisclosure may be implemented as a representation of the earth formationstored as information, including a graphic representation of parametervalues or variances in parameters of interest with respect to location,e.g., in 1D, 2D, or 3D. In one example, a model of the earth formationmay be maintained in a database. Modeling the earth formation maycomprise associating a portion of the formation or infrastructureproximate the borehole with the parameter value as estimated herein, togenerate or update the model. The information (e.g., data) may also betransmitted, stored on a non-transitory machine-readable medium, and/orrendered (e.g., visually depicted) on a display. Any of rendering themodels, the values, or information representing the same may be referredto herein as “displaying the parameter of interest on a display.”

The processing of the measurements by a processor may occur at the tool,the surface, or at a remote location. The data acquisition may becontrolled at least in part by the electronics. Implicit in the controland processing of the data is the use of a computer program on asuitable non-transitory machine readable medium that enables theprocessors to perform the control and processing. The non-transitorymachine readable medium may include ROMs, EPROMs, EEPROMs, flashmemories and optical disks. The term processor is intended to includedevices such as a field programmable gate array (FPGA).

The term “processor” or “information processing device” herein includes,but is not limited to, any device that transmits, receives, manipulates,converts, calculates, modulates, transposes, carries, stores orotherwise utilizes information. An information processing device mayinclude a microprocessor, resident memory, and peripherals for executingprogrammed instructions. The processor may execute instructions storedin computer memory accessible to the processor, or may employ logicimplemented as field-programmable gate arrays (‘FPGAs’),application-specific integrated circuits (‘ASICs’), other combinatorialor sequential logic hardware, and so on. Thus, a processor may beconfigured to perform one or more methods as described herein, andconfiguration of the processor may include operative connection withresident memory and peripherals for executing programmed instructions.

In some embodiments, estimation of the parameter of interest may involveapplying a model, as described herein above. The model may include, butis not limited to, (i) a mathematical equation, (ii) an algorithm, (iii)a database of associated parameters, (iv) a rule set, (v) a heuristic,(vi) a function, and (vii) other relational techniques, or a combinationthereof.

Control of components of apparatus and systems described herein may becarried out using one or more models as described above. For example, atleast one processor may be configured to modify operations i)autonomously upon triggering conditions, ii) in response to operatorcommands, or iii) combinations of these. Such modifications may includechanging drilling parameters, steering the drillbit (e.g., geosteering),changing a mud program, optimizing measurements, and so on. Control ofthese devices, and of the various processes of the system generally, maybe carried out in a completely automated fashion or through interactionwith personnel via notifications, graphical representations, userinterfaces and the like. Reference information accessible to theprocessor may also be used.

While the disclosure has been described with reference to exampleembodiments, it will be understood that various changes may be made andequivalents may be substituted for elements thereof without departingfrom the scope of the disclosure. In addition, many modifications willbe appreciated to adapt a particular instrument, situation or materialto the teachings of the disclosure without departing from the essentialscope thereof. Further embodiments may include direct measurementwireline embodiments, drilling embodiments employing a sample chamber,LWT tools, including drop subs and the like, and so on. While thepresent disclosure is discussed in the context of a hydrocarbonproducing well, it should be understood that the present disclosure maybe used in any borehole environment (e.g., a geothermal well) with anytype of downhole fluid.

While the foregoing disclosure is directed to particular embodiments,various modifications will be apparent to those skilled in the art. Itis intended that all variations be embraced by the foregoing disclosure.

1. A method of determining an acoustic parameter of a downhole fluidusing an acoustic assembly comprising a plurality of acoustic reflectorseach having at least one acoustically reflective surface at leastpartially immersed in the downhole fluid, the method comprising:estimating the acoustic parameter using a value for at least one waveproperty measured for: a first reflection received at a first acousticreceiver (R1) of a first pulse from a first acoustically reflectivesurface located a first distance from the first acoustic receiver; asecond reflection received at the first acoustic receiver (R1) of thefirst pulse from a second acoustically reflective surface located asecond distance from the first acoustic receiver different than thefirst distance; a first reflection received at a second acousticreceiver (R2) of a second pulse from a third acoustically reflectivesurface located a third distance from the second acoustic receiver; asecond reflection received at the second acoustic receiver (R2) of thesecond pulse from a fourth acoustically reflective surface located afourth distance from the second acoustic receiver different than thethird distance; wherein the first pulse, the first reflection of thefirst pulse, the second reflection of the first pulse, the second pulse,the first reflection of the second pulse, and the second reflection ofthe second pulse are each transmitted through the downhole fluid.
 2. Themethod of claim 1, wherein the at least one wave property comprisestravel time and amplitude.
 3. The method of claim 1, wherein the firstacoustically reflective surface comprises a portion of a first acousticreflector having a first impedance value and the second acousticallyreflective surface comprises a portion of a second acoustic reflectorhaving a second impedance value substantially the same as the firstimpedance value.
 4. The method of claim 3, wherein the thirdacoustically reflective surface comprises a portion of a third acousticreflector having a third impedance value and the fourth acousticallyreflective surface comprises a portion of a fourth acoustic reflectorhaving a fourth impedance value substantially different than the thirdimpedance value.
 5. The method of claim 4, wherein the fourth impedancevalue is substantially the same as at least one of: i) the firstimpedance value, and ii) the second impedance value.
 6. The method ofclaim 1, wherein the third acoustically reflective surface comprises aportion of a third acoustic reflector having a third impedance value andthe fourth acoustically reflective surface comprises a portion of afourth acoustic reflector having a fourth impedance value substantiallydifferent than the third impedance value.
 7. The method of claim 1,wherein the first acoustically reflective surface comprises a portion ofa first acoustic reflector having a first impedance value and the thirdacoustically reflective surface comprises another portion of the firstacoustic reflector having first impedance value.
 8. The method of claim1, further comprising transmitting acoustic pulses using at least oneacoustic transducer to generate the plurality of acoustic pulsereflections.
 9. The method of claim 1, wherein the first distance isless than the second distance and the third distance is less than thefourth distance, and estimating the acoustic parameter comprisesestimating an acoustic impedance for the downhole fluid using animpedance of the third acoustically reflective surface and an impedanceof the fourth acoustically reflective surface different than theimpedance of the third acoustically reflective surface.
 10. The methodof claim 9, wherein the third acoustically reflective surface comprisesa lower acoustic impedance material and the fourth acousticallyreflective surface comprises a high acoustic impedance material.
 11. Themethod of claim 1, wherein estimating the acoustic parameter comprisesestimating an acoustic impedance for the downhole fluid using a ratio ofa first product of the first reflection received at the first acousticreceiver and the second reflection received at the second acousticreceiver to a second product of the second reflection received at thefirst acoustic receiver and the first reflection received at the secondacoustic receiver.
 12. The method of claim 11, wherein the firstdistance is less than the second distance and the third distance is lessthan the fourth distance.
 13. The method of claim 1, wherein estimatingthe acoustic parameter comprises estimating an attenuation coefficientfor the downhole fluid using a ratio of a first value for a split-signalamplitude of the first reflection received at the first acousticreceiver and a second value for a split-signal amplitude of the secondreflection received at the first acoustic receiver.
 14. A method ofdetermining an acoustic parameter of a downhole fluid using an acousticassembly comprising a plurality of acoustic reflectors each having atleast one acoustically reflective surface at least partially immersed inthe downhole fluid, the method comprising: transmitting a plurality ofpulses; measuring values for at least one wave property measured forreflections of the plurality of pulses received at at least one acousticreceiver, including: a first value for a first reflection traveling afirst known distance from a first acoustically reflective surface havinga first known acoustic impedance; a second value for a second reflectiontraveling a second known distance substantially the same as the firstknown distance from a second acoustically reflective surface having asecond known acoustic impedance substantially different than the firstacoustic impedance; and a third value for a third reflection traveling athird known distance substantially different from each of the firstdistance and the second distance from a third acoustically reflectivesurface having a third known acoustic impedance substantially the sameas the second acoustic impedance; and estimating the acoustic parameterusing the values; wherein the plurality of pulses and the reflectionsare each transmitted through the downhole fluid.
 15. The method of claim14, wherein each of the first value, the second value, and the thirdvalue is substantially different from others of the first value, thesecond value, and the third value.
 16. The method of claim 14, whereinat least two of the first reflection, the second reflection, and thethird reflection are reflections of a particular pulse.
 17. The methodof claim 14, wherein the first known distance is a distance from thefirst acoustically reflective surface to an acoustic receiver during themeasuring, the second known distance is a distance from the secondacoustically reflective surface to the acoustic receiver during themeasuring, and the third known distance is a distance from the thirdacoustically reflective surface to the acoustic receiver during themeasuring.
 18. The method of claim 17, wherein the acoustic receiver isconfigured to rotate about an axis of the assembly, and wherein thefirst acoustically reflective surface, the second acousticallyreflective surface, and the third acoustically reflective surface areazimuthally distributed about the axis, such that each of the firstreflection, the second reflection, and the third reflection each returnto the acoustic receiver from a different azimuth with respect to theaxis.
 19. An apparatus for determining an acoustic parameter of adownhole fluid in a borehole, the apparatus comprising: a tool havingdisposed thereon an acoustic assembly, the acoustic assembly comprisingat least one transducer and a plurality of acoustic reflectors havingacoustically reflective surfaces; wherein the tool is configured to atleast partially immerse at least one transducer and the acousticallyreflective surfaces, and wherein the acoustic assembly is configured toi) transmit a plurality of pulses through the fluid, and ii) measurevalues for at least one wave property for reflections of the pluralityof pulses, including: a first value for a first reflection traveling afirst known distance from a first acoustically reflective surface havinga first known acoustic impedance; a second value for a second reflectiontraveling a second known distance substantially the same as the firstknown distance from a second acoustically reflective surface having asecond known acoustic impedance substantially different than the firstacoustic impedance; and a third value for a third reflection traveling athird known distance substantially different from each of the firstdistance and the second distance from a third acoustically reflectivesurface having a third known acoustic impedance substantially the sameas the second acoustic impedance; and a processor configured to estimatethe acoustic parameter using the values.
 20. The apparatus of claim 19,wherein the at least one transducer is configured to rotate about anaxis of the assembly; and wherein the first acoustically reflectivesurface, the second acoustically reflective surface, and the thirdacoustically reflective surface are azimuthally distributed about theaxis, such that each of the first reflection, the second reflection, andthe third reflection each return to the acoustic receiver from adifferent azimuth with respect to the axis.